1. Field of the Invention
The invention relates generally to a system for treating well fluids.
2. Background Art
When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroleum bearing formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, implacing a packer fluid, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
In drilling some subterranean formations, and particularly those bearing oil or gas, hydrogen sulfide accumulations are frequently encountered. The circulation of well fluid brings the hydrogen sulfide from the formation to the surface. Such sulfide in the well fluid is problematic, as it can corrode the steel in the drilling apparatus and may be liberated into the atmosphere as toxic sulfide gas at the well surface. Further, hydrogen sulfide contaminated oil from the well fluid may become associated with or absorbed to the surfaces of the cuttings that are removed from the formation being drilled. The cuttings are then an environmentally hazardous material, making disposal a problem.
Generally, to protect the health of those working with the well fluid and those at the surface of the well, conditions should be maintained to ensure that the concentration of hydrogen sulfide released from the fluid, emitted due to the partial pressure of the gas, is less than about 15 ppm. The partial pressure of hydrogen sulfide at ambient temperatures is a function of the concentration of sulfide ions in the fluid and the pH of the fluid. To ensure that the limit of 15 ppm is not exceeded even for the maximum sulfide concentration that may be encountered in a subterranean formation, the pH of the well fluid is typically maintained at a minimum of about 11.5. Also, to prevent the soluble sulfide concentration in the well fluid from becoming excessive, action is routinely taken to remove sulfide from the well fluid.
Dissolved gases cause many problems in the oil field. Gases and other fluids present in subterranean formations, collectively called reservoir fluids, are prone to enter a wellbore drilled through the formation. In many cases, dense drilling fluids, completion brines, fracturing fluids, and so forth are provided to maintain a countering pressure that restrains the reservoir fluids from entering the wellbore. However, there are many instances where the counter pressure is too low to restrain the reservoir fluids. This may be due to, for example, a miscalculation of the fluid density needed to maintain a hydrostatic overbalance or a transient lowering of pressure due to movement of the drill string in the hole. Gasses may also enter the wellbore through molecular diffusion if there is insufficient flux of fluid from the wellbore to keep it swept away. Finally, reservoir fluids escape from the fragments of the formation that are being drilled up. The reservoir fluid that enters the well is then free to mix with the supplied well fluid and rise to the surface.
The hazards of unrestrained expansions of reservoir fluids in the wellbore are well known. A primary hazard is an avalanche effect of gas evolution and expansion, wherein gas bubbles rise in a liquid stream, expanding as they rise. As the bubbles expand, they expel dense fluid from the bore, and further reduce the hydrostatic pressure of the wellbore fluid. Such a progression may eventually lead to a ‘blow out,’ whereby so much restraining pressure has been lost that the high pressure reservoir can flow uncontrollably into the wellbore.
Less dramatic, but equally important, are chemical effects that formation fluids may have upon the circulating fluid, the structure of the well, and the associated personnel. These effects and risks may include, for example: methane gas liberated at the surface may ignite; carbon dioxide may become carbonic acid, a highly corrosive compound, when exposed to water; carbon dioxide gas is an asphyxiant; hydrogen sulfide can corrode ferrous metals, particularly in contact with water, and is more damaging than carbon dioxide because it can induce hydrogen embrittlement; embrittled tubulars may separate or break well under design stresses with catastrophic consequences; hydrogen sulfide gas is also toxic, with levels of 800 to 1000 ppm causing death in healthy individuals. Removing dissolved and entrained gases is thus vital to many aspects of successful drilling and exploitation.
Chemical processes have been previously used to ameliorate the effects of dissolved gasses, particularly of hydrogen sulfide and carbon dioxide. Caustic and similar high-pH materials, for example, sodium hydroxide, are added to circulating well fluid to maintain pH. Copper, zinc, and iron compounds have been added to react with and sequester hydrogen sulfide, although they often have deleterious effects on circulating fluid properties and can cause environmental disposal issues. Oxidants, such as hypochlorite, have also been proposed, but they may have destructive effects on organic and metal components.
Accordingly, there exists a need for a method and apparatus to facilitate the removal of entrained and dissolved gases in a well fluid. Further, there exists a need for a method and apparatus to facilitate the destruction and removal of hydrogen sulfide in a well fluid.